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Patent 2864963 Summary

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(12) Patent Application: (11) CA 2864963
(54) English Title: METHOD OF REMOVING WELLBORE FLUID FROM WELL AND WATER REMOVAL WELL
(54) French Title: PROCEDE DE RETRAIT DE FLUIDE DE PUITS DE FORAGE D'UN PUITS ET PUITS D'EVACUATION D'EAU
Status: Dead
Bibliographic Data
(51) International Patent Classification (IPC):
  • E21B 43/12 (2006.01)
  • E21B 47/008 (2012.01)
(72) Inventors :
  • STORM, BRUCE HARRISON (United States of America)
(73) Owners :
  • SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V. (Netherlands (Kingdom of the))
(71) Applicants :
  • SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V. (Netherlands (Kingdom of the))
(74) Agent: NORTON ROSE FULBRIGHT CANADA LLP/S.E.N.C.R.L., S.R.L.
(74) Associate agent:
(45) Issued:
(22) Filed Date: 2014-09-23
(41) Open to Public Inspection: 2015-03-25
Availability of licence: N/A
(25) Language of filing: English

Patent Cooperation Treaty (PCT): No

(30) Application Priority Data:
Application No. Country/Territory Date
61/882,121 United States of America 2013-09-25

Abstracts

English Abstract



A method for removal of fluid from a subterranean formation is provided, the
method including the steps of: providing a wellbore from the surface to within
the
formation: providing a pump in the wellbore capable of removing fluid from the
wellbore
to a surface location; establishing a pump performance function as pump
curves;
measuring at least one variable that establishes where the pump is operating
on the pump
curve; determining the differential pressure across the pump from the measured
variable
and the digitalpower and the flow rate; determining the suction side pressure
from the
differential pressure across the pump and the vertical height of the annular
fluid column of
the fluid column above the pump; determining the suction side fluid level from
the suction
side pressure and the fluid density.


Claims

Note: Claims are shown in the official language in which they were submitted.



WHAT IS CLAIMED IS:

1. A method for removal of fluid from a subterranean formation comprising
the steps
of:
providing a wellbore from the surface to within the formation:
providing a pump in the wellbore capable of removing fluid from the wellbore
to a
surface location;
establishing a pump performance function as pump curves;
measuring at least one variable that establishes where the pump is operating
on the
pump curve;
determining a differential pressure across the pump from the at least one
measured
variable;
determining a pressure of liquid pumped by the electric driven pump at a know
height of the annular fluid column above the suction of the electric driven
pump;
determining a height of the annular fluid column of liquid above the suction
of the
pump from the differential pressure across the pump, the know height of the
annular fluid
column above the suction of the electric driven pump, and the pressure of
liquid pumped
by the electric driven pump at a know height of the annular fluid column above
the suction
of the electric driven pump.
2. The method of claim 1 further comprising the step of selecting a target
height of the
annular fluid column of liquid above the suction of the pump to which the pump
is to
maintain.
3. The method of claim 2 further comprising the step of adjusting the
output flow rate
of the pump to a flow rate which maintains the level of fluid in the wellbore
essentially at
the target height of the annular fluid column of liquid above the suction of
the pump.
4. The method of claim 3 wherein the electric pump is a variable speed
electric pump
and the step of adjusting the output flow rate of the pump is accomplished by
adjusting the
frequence of electricity to the variable speed electrical pump.

12


5. The method of claim 1 further comprising measuring the pressure in an
annulus of
the wellbore and determining the height of the annular fluid column of liquid
above the
suction of the pump from the differential pressure across the pump, the know
height of the
annular fluid column above the suction of the electric driven pump, and the
pressure of
liquid pumped by the electric driven pump at a know height of the annular
fluid column
above the suction of the electric driven pump, and the pressuer in the annulus
of the
wellbore.
6. The method of claim 1 further comprising the step of determining the
height of the
annular fluid column of liquid above the suction of the pump by independent
means in
order to calibrate the calculation of the height of the annular fluid column
of liquid above
the suction of the pump.
7. The method of claim 1 further comprising the step of producing methane
from the
subterranean formation.
8. The method of claim 1 wherein the subterranean formation is a coal
containing
formation.
9. A wellbore comprising:
an electric driven pump;
a current measuring device effective to measure the current to the electric
driven
pump and produce a signal corresponding to the current
a pressure measuring device effective to measure the pressure of liquid pumped
by
the electric driven pump and produce a signal corresponding to this pressure:
a memory device containing relationships between current, and the head
produced
by the pump; and
a controller to control the electric driven pump to maintain a predetermined
height
of the annular fluid column of liquid above the suction of the pump according
to the
relationship between the current, the variable frequency, and the head
produced by the
pump and the measured pressure of liquid pumped by the electric driven pump.
10. The wellbore of claim 9 further comprising a sensor for measuring
methane flow
rate from the wellbore wherein the controller resets the predetermined height
of the annular
fluid column of liquid above the suction of the pump to maximize net profit.

13


11. The wellbore of claim 9 wherein the pump is a variable speed electric
driven pump,
and the controller controls the frequency of alternating current to the
variable speed electric
driven pump.
12. The wellbore of claim 9 further comprising a control valve in the
wellbore fluid
production line from the electric driven pump wherein the controller controls
the position
of the control valve.
13. The wellbore of claim 9 further comprising:
a recycle line from the discharge of the electric driven pump back to the
suction of
the electric driven pump;
a control valve in the recycle line; wherein the controller controls the
control valve
in the recycle line to maintain the height of the annular fluid column of
liquid above the
suction of the pump.
14. The wellbore of claim 13 wherein the controller also controls the valve
in the
recycle line to maintain a predetermined minimum flow rate of liquids through
the electric
driven pump.

14

Description

Note: Descriptions are shown in the official language in which they were submitted.


CA 02864963 2014-09-23
METHOD OF REMOVING WELLBORE FLUID FROM WELL AND
WATER REMOVAL WELL
BACKGROUND
The invention relates to a method of removing wellbore fluid from a wellbore
and a wellbore for removing fluid from a formation. In particular, the present
invention
may be utilized to produce methane from coal bed methane seams by removal of
water
from the formation
Coal bed methane is typically produced by pumping water from a coal bed
methane seam to reduce the hydrostatic pressure, and thereby permit methane
adsorbed on
the coal to be released. Typically the seams from which methane may be
produced by this
method are fairly shallow, at depths from three hundred to eigth hundred
meters. The
wellbores provided to accomplish this are generally simple and inexpensive,
but removal
of water is a significant cost Generally, pumps are provided in ratholes that
extend below
the coal seam, and the pumps are operated until the liquid level in the
wellbore is low. The
pump is then shut down, and the liquid level is allowed to build. At some time
the pump is
turned on again to again lower the level of the water in the wellbore.
Constantly starting
up and shutting down the pump results in short lifes of the pumps, and having
to operate
with more than a minimal amount of water in the wellbore can reduce production
of
methane. Operators therefore attempt to optimize profits by allowing water
levels to build
for a time period, but not to an extent where excessive production is lost
because of
additional hydrostatic pressure being put on the coal.
US patent no 6,446,601 to Ocondi suggests a system for controlling the liquid
level in a coal bed methane wellbore utilizing a variable speed electric
driven submersible
pump. Flow rates of pumped liquids and produced gas are monitored along with
liquid
level in the wellbore to control the speed of the variable speed pump, and to
turn the pump
on and off as necessary, to optimize production of gas from the wellbore. The
system
suggested by Ocondi requires a level measurement within the wellbore, and
transmission
of a level signal to the surface where that level measurement may be utilized
in the control
scheme. A large number of coal bed methane wells need to be provided for a
commercial
development, and therefore the cost of each well is important to the economics
of the
development. Elimination of the wellbore liquid level measurement and the
equipment
needed to transmit the signal from that sensor to the surface would help
reduce the cost of
the well and be a desirable improvement.
1

CA 02864963 2014-09-23
SUMMARY OF THE INVENTION
A method for removal of fluid from a subterranean formation is provided, the
method comprising the steps of:providing a wellbore from the surface to within
the
formation: providing a pump in the wellbore capable of removing fluid from the
wellbore
to a surface location; establishing a pump performance function as pump
curves; measuring
at least one variable that establishes where the pump is operating on the pump
curve;
determining the differential pressure across the pump from the measured
variable and the
power; determining the suction side pressure from the differential pressure
across the pump
and the vertical height of the fluid column above the pump; determining the
suction side
fluid level from the suction side pressure and the fluid density.
The method of the present invention provides that a submersible pump can be
controlled using variables that are readily measured at the surface, avoiding
any
requirement to measure a liquid level in the wellbore.
In one embodiment, the power being consumed by the pump is determined by
measured
current and optionally voltage, and the differential pressure across the pump
is inferred
based on pump performance data. Pump performance data could be digitized, or
expressed as, for example, a polynomial so that the process could be automated
and
incorporeated into a continuous control scheme. A measured pressure at the
surface for the
suction side of the pump (normally the annulus) and the discharge side (liquid
line at the
well head) could then be used to determine the liquid level at the suction of
the pump. In
some embodiments of the present invention, the data used to control the liquid
level, along
with measured methane production, may be used to vary the liquid level to
optimize the
point to which the liquid level in the wellbore is controlled.
In another embodiment of the present invention, a variable speed pump may be
utilized to avoid cycling the pump between running and being shut down, along
with
minimizing or avoiding energy loss across a control valve for the liquid
discharge.
In another embodiment of the present invention, the differential pressure
across
the pump may be inferred from pump performance data and a measured flow rate
of
pumped liquids.
BRIEF DESCRIPTION OF THE FIGURES
Figure 1 is an explanary drawing of a pump curve as head as a function of
speed
and power
2

CA 02864963 2014-09-23
'
=
Figure 2 is a schematic drawing of the well of the present invention.
DETAILED DESCRIPTION
Figure 1 is an exemplary pump curve figure. Line 1 shows a function of head
in the vertical axis as a function of flow rate on the horizontal axis for a
particular speed.
Lines 2 thorugh 4 show the same curves for progressively lower speeds. Line 10
shows
pump horsepower on the vertical axis as a function of flow rate on the
horizontal axis,
again for one pump speed. Lines 11 thorugh 13 show the same curves for
progressively
lower speeds. Line 20 shows system efficiency as a function of flow rate for
one pump
speed, and lines 21 through 23 show this function for progressively lower pump
speeds.
Curves like this are available for commercially available pumps from the
manufactures or
marketers of the pumps.
The pump curves like those shown in Figure 1 could be expressed, for example,
as polynomials where power and head are given as a function of flow rate and
speed, or
alternately, the head could be determined as a function of flow rate and power
consumption.
These functions could be determined, for example, by performing a least
squares fit to
pump performance data obtained from the pump manufacture or vendor or obtained
by
measured performance for the specific model of pump utilized. Obtaining or
creating a
digital model of the pump performance enables a computer, programmable logic
controller,
or other automated means to convert easily measured parameters to determine
the head of
wellbore fluid above the suction of the down hole pump without having to use a
down-hole
level measurement and transmitter.
Hydraulic power required to pump fluid at a specified rate depends on the
pressure against which the submersible pump is required to work, or the
differential
pressure across the pump that the pump provides. In the case of a submersible
pump, the
differential pressure across the pump is dictated by the difference in the
level of the fluid
columns on the input and output sides of the pump, the density of the fluid,
the pressure
applied to the top of each fluid column, and any pressure resulting from flow
friction.
The pressure drop resulting from flow friction in the output tubular may be
calculated from the fluid properties (density and viscosity), geometry of the
tubular (length
and diameter) and the flow rate by methods well known in the art. For
relatively short flow
lines with low viscosity fluid, the friction effects are minor and in some
embodiments may
be ignored with little effect on subsequent calculations.
3

CA 02864963 2014-09-23
=
In one embodiment, the pressure applied to the top of the annular fluid
column,
or the suction side of the submersible pump, is close to that applied to the
top of the outlet
fluid column, or the discharge of the submersible pump. In this example, the
submersible
pump maybe pumping fluids from the wellbore to a separator at the surface
which is at
essentially the same pressure as vapor in the annulus of the wellbore. This
could be the
case if, for example, a vapor space above a liquid level in a separator vessel
at the surface
is in communication with the same system that compresses methane production.
Additionally, friction effects from the flow of the fluids being pumped
through the tubular
extending from the submersible pump discharge to the wellhead are relatively
small. In
this embodiment, the differential pressure across the pump is given by the
product of the
fluid density, the acceleration due to gravity and the difference in the
height of the fluid
columns on either side of the pump. Hence, the height of the annular fluid
column, or
above the suction of the pump, may be determined from the differential
pressure across the
pump and the height of the fluid column above the submersible pump outlet.
This differential pressure across the pump may be calculated by first
measuring
the power consumed by the motor in driving the submersible pump. If the
submersible
pump is powered by an electric motor, this may be accomplished by measuring
both the
voltage and the current and determining the power as the product of the
measured voltage
and current. In cases where a constant voltage power supply is utilized, the
power may be
determined by measuring the current and multiplying the measured current by
the fixed
voltage. Other methods of determining the supplied power are known in the art
for other
power sources. For example, fuel consumption may be used to determine the
input power
for an internal combustion engine.
The next step involves measuring the output flow rate of the pump, and from
pump curves, determining the efficiency for the pump at this flow rate. The
system
efficiency is defined as the ratio of output power to input power and is
generally
determined from manufacturer supplied pump curves. In some cases, the system
efficiency
may be taken to be nearly constant over a relevant range of operating
conditions.
The hydraulic power may then be calculated by multiply the electrical power by

the efficiency.
The differential pressure across the pump is calculated by dividing the
hydraulic
power by the flow rate.
4

CA 02864963 2014-09-23
=
The hydraulic head may be determined by dividing the differential pressure
across the
pump by the product of the fluid density and the acceleration due to gravity.
The height of the annular fluid column is then given by subtracting the
hydraulic head from the depth of the pump where the depth of the pump is taken
from the
suction of the pump to the elevation of the discharge of the pump at the
surface. The
height of the annular fluid column could alternatively be taken with reference
to any
reference elevation, so long as the same reference elevation is used to
measure the depth of
the pump.
Thus the height of the annular fluid column is determined based on measured
flow rate, measured electrical power use, and determining the efficiency from
pump curves,
and variables that can generally assumed to be constant such as liquid density
and the
height of liquid above the discharge of the pump.
There are a number of permutations on the ordering of the steps which lead to
the same results as the above method. Further, there are a number of
additional corrections
that could be made, for example, by measuring and inputting into the
calculations variables
such as the pressures at, for example, the wellhead, for the discharge and
suction side of
the pump, or takng into account frictional pressure drop of the fluids flowing
through the
tubular.
In another embodiment, the differential pressure across the pump may be
determined by measuring the flow rate of well fluids, and knowing the density
of the well
fluids, and then determining the differential pressure across the pump
directly from pump
curves. The difference between this differential pressure across the pump,
after conversion
to the equivelant height of liquid, and the known height of liquid between the
pump outlet
and the surface, would correspond to the height of the annular fluid column,
or the liquid
above the suction of the submersible pump. As with the previously described
embodiment,
this result could also be corrected for differences between the pressure in
the annulus and
the pressure above liquids at the surface, or frictional pressure loss of the
wellbore fluids
being pumped through the tubular.
A correction could also be made for the additional pressure exerted by the
head of
the vapor column above the suction of the pump. This could be a small
correction. For
example, a one thousand foot head of methane at a pressure of twenty two
pounds per
square inch absolute and at 20 C would add a pressure of 0.44 pounds per
square inch
pressure to the suction of the downhole pump, or about one foot of water at
standard

CA 02864963 2014-09-23
conditions. If data such as the gas temperature, pressure and composition are
available,
then this correction could be made based on the actual conditions. When the
temperature,
pressure, and compositions of gas in the annulus of the wellbore do not change

significantly over time, typical values for the unavailable variables could be
used to
calculate a constant correction due to the head of the vapor column on the
suction of the
pump.
For a constant speed pump, the above method arrives at the head of liquid in
the
wellbore using the efficiency from the pump curves, the measured flow rates
and the
measured pressure in the vapor space in the wellbore and the pumped fluid
pressure at the
surface.
Refering now to Figure 2, an example of a wellbore of the present invention is

shown. A well 201 is shown extending through a coal seam, 202 with a rat hole
exending
into formation below the coal seam 203, and through overburden 204. A surface
casing,
205 may be cemented with cement 206 to a depth below aquifers to protect water
supplies.
Often wells in coal bed methane production services are provided with cemented
casings
below this depth, but are provided with an uncemented liner 207. An annulus
around the
uncemented liner may be sealed by, for example, packers 208. A plurality of
packers could
be provided, and the packers could be, for example, swellable polymers that
expand upon
contact with water.
An electrical submersible pump 209 may be provided, preferably below the
level of the coal seam within the wellbore. The electrical submersible pump
may be
suspended by a tubular 210 from a wellhead 211, and provided electrical power
by a power
cable 212 that extends through the wellhead 211 through, for example, a packer
213, from,
for example, a transformer 214 which converts power line voltage power, 217,
tovoltages
capable of being transmitted to the electrical submersible pump. The
transformer may be
equipped with a meter and transmitter for current 215 and voltage 216 for
determination of
electrical power being consumed by the electrical submersible pump 209.
The wellbore 201 may contain a liquid level 218, which is at a height of the
annular fluid column 219 above the suction of the submersible pump 209, to be
measured
and controlled by the present invention. When the present invention is applied
to a coal
bed methane production well, the liquid level is lowered from a normal
equiblibrium level,
which could be the water table of the overburden, thus lowering the pressure
excerted on
the coal within the coal seam 202. As a result of the lower pressure, methane
that is
6

CA 02864963 2014-09-23
adsorbed on the surface of the coal is released and produced through the
annulus of the
wellbore 220 and through the wellhead 211, via a nozzle 221, in the wellhead.
The rate at
which methane is produced is typically measured by, for example, an orfice
meter 222.
The methane production 223 is typically increased by minimizing the liquid
level in the
wellbore to the constraints of the requied net positive suction head required
for reliable
operation of the pump 209, to permit maxium release of methane from the coal
seam.
Ashut-in valve 224 could be provided in the gas production line to permit
isolation of the
well.
When operating, the electrical submersible pump 209 pumps well fluids
through the tubular 210 and through the wellhead 211 to a liquid production
line 225.
When the present invention is practiced in a coal bed methane production well,
the well
fluid is mostly water, potentially contining dissolved methane and possibly
other
contaminates such as carbon dioxide, hydrogen sulfide, and heavier
hydrocarbons.
Pressure of the pump discharge at the surface may be measured by pressure
transmitter 226,
and the flow rate of the wellbore liquids being pumped may be measured by flow

transmitter 227. The liquids being pumped could be routed to a separator 332,
where a
liquid level 333 could be maintened allowing additional methane to escape 334
from the
pumped liquids, producing a degassed pumped liquid stream 335. In this
embodiment, the
depth of the pump 336 would be the distance from the liquid surface in the
separator to the
suction of the pump, or another point of reference which is used to determine
the height of
the annular fluid column 219.
In some embodiments, the liquid production line 225 may be provided with a
flow control valve 228. When a flow control valve 228 is provided, the depth
of the pump
would need to consider the distance between the suction of the pump and the
elevation of
the sensor for the pressure transmitter 226, of distance 337, plus the
pressure measured by
the pressure transmitter. The pressure measured by the pressure transmitter
would be
converted to a height of liquids by dividing the pressure by the product of
the density of the
wellbore fluids and the acceleration of gravity.
A controller 229 may be provided to control the height of the annular fluid
column 219 of liquids within the wellbore. The controller utilizes inputs from
variables
that are measured at the surface to control the height of the annular fluid
column 219 of
liquids within the wellbore. There are different combinations of variables
that could be
utilized within the scope of the present invention, and there are different
control variables
7

CA 02864963 2014-09-23
,
within the scope of the present invention. Height of the annular fluid column
219 of
liquids in the wellbore may be controlled by turning on and off the electrical
submersible
pump 209. This method of control is not preferred because it may result in the
height of
the annular fluid column 219 increasing above a minimal height of the annular
fluid
column while the pump is not operating, possibly resulting in a hydrostatic
pressure on the
formation that exceeds the optimal operating pressure. In the application of a
coal bed
methane production well, this may result in marginally reduced production from
the well.
Further, constantly turning on and off electrical pumps is detrimental to the
service life of
the pump.
The height of the annular fluid column 219 could be controlled by controlling
the flow control valve 228 for the liquid production. When the flow of liquid
production is
controlled to control the height of the annular fluid column 219, the
controller 229, could
also maintain a minimum flow rate. In this embodiment control signal 230 goes
to flow
control valve 228 to control the positon of the flow control valve to maintain
the height of
the annular fluid column of liquid. The height of the annular fluid column of
liquid may be
controlled directly from the height of the annular fluid column determined by
the present
invention, or the height of the annular fluid column determined by the present
invention
could reset a set point for the flow rate measured by flow transmitter 227,
and the flow rate
measured by flow transmitter 227 controlled.
Maintenance of a minimum flow rate may be desirable to prevent the pump
from over heating or prevent the pump from being damaged or causing the life
of the
pump to be shorted by operation at less than desired flow rates. Minimum rates
could be
maintained by, for example, shutting down the pump when minimum height of the
annular
fluid column are reached, and then starting the pump back up after a
predetermined time
period. Alternatively, the minimum flow rate could be maintained by recycling
some
produced fluids back into the wellbore.
When a variable speed pump is utilized, the speed of the pump may be
controlled to control the height. Typically, variable speed motors are
controlled by
changing the frequency of alternating current provided to the electrical
motor. In this
embodiment, transformer 214 maybe a variable speed well level controllers are
commercially available, for example, from Yaskawa. The iQpump drive, from
Yaskawa,
is for example, an exemplary variable speed pump controller.
8

CA 02864963 2014-09-23
Controller 229 could utilize as inputs, for example, one or more of the
current
215 and voltage 216 for determination of electrical power being consumed by
the electrical
submersible pump 209, annulus pressure 230, pressure of the pump discharge at
the surface
as measured by pressure transmitter 226, and the flow rate of the wellbore
liquids being
pumped as measured by flow transmitter 227. The controller could then provide
a control
signal 231 which would, for a constant speed pump, control the position of the
flow control
valve 228. In the practice of the present invention, where a variable speed
pump is utilized,
the control signal could control the speed of the variable speed pump by
reseting the input
to the variable speed well level controller 214.
Controller 229 could provide additional functions. For example, when input to
the controller indicates that the pump is cavitating or has insufficient
suction head pressure,
the control system could be overridden to shut down the pump. An indication
that the
pump is cavating could be, for example that power consumption decreasing below
a
predetermined threshold, In this embodiment, the height of liquids in the
annular fluid
column to which the controller is set to control could be reset to a height
slightly, for
example, two meters to twenty meters, above the height deterimined at the
point that
cavitation is detected. Other indications that the pump may be cavitating
could be rapid
changes in current to the pump motor, or fluctuations in the rate wellbore
fluids are being
pumped. Preventing the pump from operating in a cavitation mode, or operating
with
insufficient suction head, could inproe the reliability and useful life of the
pump, and also
avoid energy costs incurred when the wellbore contains insufficient liquids to
be pumped.
In an application of the present invention to a coal bed methane well, the
controller 229 could also consider the rate at which methane being produced,
as measured
by orfice meter 222 along with in the cost of disposing wellbore fluid removed
from the
wellbore, to optimize the height of the annular fluid column 219. The pump 209
could be
placed in a rat hole below the coal seem by a distance of at lease the net
positive suction
head requirement of the pump, and thus enable operation with the level of
wellbore fluid
below the entire coal seam. This would result in maximum rates of methane
release from
the coal seam, but may not result in maximum profit from the operation.
Pumping and
disposal of wellbore fluid from coal seams is a significant operating cost,
and the lower the
level of wellbore fluid is carried in the wellbore, the more wellbore fluid
would need to be
pumped and disposed. Therefore there may be an optimum height of the annular
fluid
column, 219, which would result in a maximum difference between the value of
produced
9

CA 02864963 2014-09-23
-
methane and cost of pumping and disposing of wellbore fluid. The controller
could, on a
regular basis, change the set point to which the height of the annular fluid
column 219 is
maintained, and determine if the change in value of methane production
exceeded the
change in the cost to pump and dispose of wellbore fluid. If the incremental
change in the
height of the annular fluid column 219 resulted in a greater net profit, then
the set point
could be reset to the new set point for the height of the annular fluid column
219.
Controller 229 could also be configured to maintain the flow rate of wellbore
fluid being pumped to a rate that exceeds minimum rates for the pump.
Generally, pumps
have minimum rates below which they will suffer short services lifes at least
partilly
because of higher operating temperatures. If this minimum rate cannot be
achieved
without the height of the annular fluid column 219 falling below a minimum, as
required
for example, by net positive suction head requirements, then the controller
could cause the
pump to shut down for a predetermined time. The pump could be restarted after,
for
example, a predetermined time. Pumping would be resumed at a rate that would
exceed
the minimum rates established for the pump. The predetermined time period
could be reset
by the controller based on the height of the annular fluid column measured at
the time the
pump is restarted.
When the present invention is practiced in a coal bed methane production
application, letting the liquid level in the wellbore raise too high results
in excessive loss of
methand production due to the increased hydrostatic pressure on the coal seam.
Starting
the pump up too soon will result in excessive cycles of starts and stops for
the pump, and
shorten the service life of the pump. The controller could be provided with,
for example a
ratio between the resulting difference in height of the annular fluid column
291 and shut
down times for reseting the predetermined time the pump is shut down so the
controller
may maintain a near optimum balance between lost production and decreases in
pump
service lifes.
The present invention utilizes performance curves supplied by the manufacture
or vendor although the performance of pumps may deterioriate over time for
many reasons.
The present invention may therefore include a step of calibrating the pump
curves
occasionally by utilizing an independent means to measure the height of the
annular fluid
column 219 and adjusting the pump curves to match the current measured
performance.
The height of the annular fluid column 219 could be occasionally determined
manually by an accustic level measuring device which could be connected to the
wellbore

CA 02864963 2014-09-23
=
at the surface. These devices are know and commercially available, for
example, LMSA
500 portable liquid level monitoring sysgem is an example of an acceptable
portable
sysgem available from EPG Companies, 19900 County Road 81, Maples Grove, MN
55311. Mobrey MSP900FH ultrasonic level sensor is also an acceptable system..
The recalibration could also be used to correct the height of the annular
fluid
column for small variables such as the pressure on the suction casued by the
head of vapor
in the annulus of the well.
11

Representative Drawing
A single figure which represents the drawing illustrating the invention.
Administrative Status

For a clearer understanding of the status of the application/patent presented on this page, the site Disclaimer , as well as the definitions for Patent , Administrative Status , Maintenance Fee  and Payment History  should be consulted.

Administrative Status

Title Date
Forecasted Issue Date Unavailable
(22) Filed 2014-09-23
(41) Open to Public Inspection 2015-03-25
Dead Application 2018-09-25

Abandonment History

Abandonment Date Reason Reinstatement Date
2017-09-25 FAILURE TO PAY APPLICATION MAINTENANCE FEE

Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Application Fee $400.00 2014-09-23
Maintenance Fee - Application - New Act 2 2016-09-23 $100.00 2016-09-22
Owners on Record

Note: Records showing the ownership history in alphabetical order.

Current Owners on Record
SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V.
Past Owners on Record
None
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.
Documents

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Document
Description 
Date
(yyyy-mm-dd) 
Number of pages   Size of Image (KB) 
Cover Page 2015-03-31 2 58
Abstract 2014-09-23 1 22
Description 2014-09-23 11 607
Claims 2014-09-23 3 107
Drawings 2014-09-23 2 49
Representative Drawing 2015-02-19 1 20
Assignment 2014-09-23 4 155